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The label unconventional resources, for shale or other nontraditional oil and gas formations, has its detractors. Bruce Vincent, president of Swift Energy, said in a speech in August that "it is not unconventional any more." The problem, he explained, was that "unconventional sounds unreliable," despite the large and growing volumes produced by companies like Swift, an independent whose operations include the Eagle Ford Shale. But those on the technology-development side of the industry describe unconventional development as a precocious newcomer that has achieved much, with the US predicted to be the world's largest producer by the end of the decade, but it is far from mature. When SPE's six technical directors were asked to talk about some of their priorities for technology development in unconventional reservoirs, they pointed to the areas where change is needed to realize the potential for resources. On the list are improved reserve estimates, adding flexibility to standardized drilling and completion methods, and a greater focus on what it will take to maximize long-term production. A word used over and over by Vincent and the tech directors was optimizing.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.34)
Abstract The tremendous efforts have been made by the industry in tapping the recoverable resources from the unconventional reservoirs in the past ten years. Shale (tight) gas and shale (tight) oil are the two typical ones. Some research studies focused on the effect of porous media on the dew point of gas condensates in terms of experimental and theoretical work. The contradictory conclusions were reached. On the other hand, some conclusions were made for crude oil as well on the basis of the measurements of the bubble point pressure of crude oil in porous media. Therefore, it is of great importance to develop an effective method to predict the phase behavior of shale gas and shale oil in porous media and investigate the effects of some factors on the saturation pressures of gas condensate and crude oil in tight reservoirs. In this paper, a general framework of theoretical models has been developed to predict the saturation pressures of shale gas and shale oil in tight reservoirs. The Laplace equation is used to relate to the pressures in vapor and liquid phases from the curved interface. The Parachor model is applied to determine the interfacial tensions of crude oil and gas condensate. By taking into account of porous media in the proposed models, the calculations have been performed in some case studies. The effect tendency of some properties of porous media such as permeability and porosity on the dew or bubble point of reservoir fluid is discussed in this paper.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (4 more...)
Abstract Openhole, multi-stage fracturing systems are commonly used today in many applications, including unconventional shale gas reservoirs. As many as forty stages have been successfully completed in a single horizontal well and the industry is aiming even higher. One problem that has a major impact on job success is the ability to accurately calculate maximum pump rates for a given surface pump pressure. When frac fluid is pumped through a downhole multi-stage fracturing system, each time a new stage is completed, the flow splits at different sleeves in the completion string. To determine minimum surface pump pressure and maximum pump flow rate, predicting split flow rate and the resulting pressure loss at each stage is essential. Traditionally, laboratory tests and field experience are used to predict these values. However, these types of predictions are not possible for hydraulic fracturing jobs that use a multiple sliding sleeve system, as is commonly employed. To simulate the hydraulic fracturing process, the Computational Fluid Dynamics (CFD) approach has been used, as it is a proven methodology. However, extensive CFD analysis requires computational overhead and significant software and hardware costs. This paper presents a methodology which combines CFD and theoretical approaches to calculate split flow rate and pressure loss for non-Newtonian frac fluids in a multiple sliding sleeve system. These methods are incorporated into the multiple sliding sleeve design process and hydraulic fracturing plan optimization. The method can also be extended as a general solution for calculating pressure loss due to split flow.
- North America > United States > Texas (0.68)
- Europe (0.68)
Abstract Various forms of shale gas (SG) material balance equations (MBE) have been developed in the past several decades, dating back to the first round of coalbed methane (CBM)/SG development in North America. These equations attempt to incorporate various aspects of SG storage mechanisms and reservoir characteristics; simple to complex forms exist, depending on the number of assumptions made in their derivation. All of the equations account for adsorbed gas storage, but may or may not include corrections for pore volume (PV) and fluid compressibility, water influx etc. In higher-permeability fractured SG and CBM plays, application of material balance using static (shut-in) pressures to derive original gas-in-place (OGIP) and drainage area estimates has proven useful. With the current development of ultra-low permeability SG (and shale liquids) plays, shut-in times for wells is impractically long so as to preclude the use of static material balance (SMB) methods. Use of rate-transient analysis (RTA) techniques, such as the flowing material balance (FMB), is much more common for original gas-in-place (OGIP) derivations in ultra-low permeability reservoirs, yet some form of MBE is often required for application of these methods. For example, pseudo-time and material balance pseudo-time is commonly used in advanced RTA methods, and hence the form of MBE could impact reservoir and/or hydraulic fracture properties derived from the analysis. In this work, we first summarize the MBEs that have been derived specifically for SG and/or CBM, with an emphasis on the assumptions, limitations and applications of each equation. We then derive a new MBE that dynamically adjusts free-gas storage volume during depletion according to the amount of volume occupied by sorbed gas, as recently suggested by Ambrose et al. (2010) for volumetric gas-in-place determination. Finally, we examine the impact of MBE selection on quantitative rate-transient analysis (for estimation OGIP). Two simulated cases for SG reservoirs are used to demonstrate the impact of the selected MBE. Finally, a modified transient productivity index (PI) using average pressure in the region of influence was developed and is compared to conventional transient PI. The results of this study are of interest to those engineers performing unconventional reservoir characterization work using RTA and for reserves estimators.
- North America > United States > Texas (0.93)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Michigan > Michigan Basin > Antrim Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
Abstract Unconventional shale gas resources have become a major component of the energy mix in North America, with future growth projected globally. The nature of storage and transport of hydrocarbon gas are not yet fully understood in these plays. Adsorption in gas shales is expressed by the Langmuir isotherm, which is the capacity of the rock to adsorb gas at any given temperature. The Langmuir isotherm is generally measured in the laboratory with crushed rock samples. In the presence of CO2 with CH4 in the free gas state, the desorption behavior and measurement becomes more complex. There are significant differences in sorption experimental procedures and results reported by different vendors. This study addresses the challenges in data variability in sorption measurement, the differences in EUR and GIP calculations, including existing limitations on adsorption measurement and reporting techniques. The results and implications of round- robin experiments with four different samples across four vendor laboratories are shown with multi-component adsorption isotherm analysis. The limitations and variations based on vendor data measurement techniques for accurately calculating GIP and EUR in the case of multi-component adsorption are discussed.
- North America > United States (1.00)
- North America > Canada > British Columbia (0.15)
Integration of Shale Gas Production Data and Microseismic for Fracture and Reservoir Properties Using Fast Marching Method
Xie, Jiang (Texas A&M University) | Yang, Changdong (Texas A&M University) | Gupta, Neha (Texas A&M University) | King, Michael J. (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University)
Abstract We present a novel approach to calculate drainage volume and well performance in shale gas reservoirs using a Fast Marching Method (FMM) combined with a geometric pressure approximation. Our approach can fully account for complex fracture network geometries associated with multistage hydraulic fractures and their impact on the well pressure and rates. The major advantages of our proposed approach are its simplicity, intuitive appeal and computational efficiency. For example, we can compute and visualize the time evolution of the well drainage volume for multimillion cell geologic models in seconds without resorting to reservoir simulation. A geometric approximation of the drainage volume is then used to compute the well rates and the reservoir pressure. The speed and versatility of our proposed approach makes it ideally suited for parameter estimation via inverse modeling of shale gas performance data. We utilize experimental design to perform the sensitivity analysis to identify the โheavy hittersโ and a genetic algorithm to calibrate the relevant fracture and matrix parameters in shale gas reservoirs by history matching of production data. In addition to the production data, microseismic information is utilized to help us constrain the fracture extent and orientation and to estimate the stimulated reservoir volume (SRV). The proposed approach is applied to a fractured shale gas well. The results clearly show reduced uncertainty in the estimated fracture parameters and SRV, leading to improved forecasting and reserve estimation.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Texas > Sabine Uplift > Carthage Cotton Valley Field > Cotton Valley Group Formation > Cotton Valley Sand Formation (0.99)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (5 more...)
Abstract We utilize several lines of evidence to argue that slow slip on pre-existing fractures and faults is an important deformation mechanism contributing to the effectiveness of slick-water hydraulic fracturing for stimulating production in extremely low permeability shale gas reservoirs. First, we carried out rate and state friction experiments in the laboratory using shale samples from three different formations with a large range of clay content. These experiements indicated that slip on faults in shales comprised of less than about 30% clay is expected to propagate unstably, thus generating conventional microseismic events. In contrast, in formations containing more than about 30% clay are expected to slip slowly. Second, we illustrate through modeling that slip induced by high fluid pressure on faults that are poorly oriented for slip in the current stress field is expected to be slow, principally because slip cannot occur faster than fluid pressure propagates along the fault plane. Because slow fault slip does not generate high frequency seismic waves, conventional microseismic monitoring does not routinely detect what appears to be a critical process during stimulation. Thus, microseismic events are expected to give only a generalized picture of where pressurization is occurring in a shale gas reservoir during stimulation which helps explain why microseismicity does not appear to correlate with relative productivity. We review observations of long-period-long-duration seismic events that appear to be generated by slow slip on mis-oriented fault planes during stimulation of the Barnett shale. Prediction of how pre-existing faults and fractures shear in response to hydraulic stimulation can help optimize field operations and improve recovery.
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.94)
- (2 more...)
Overcoming Drilling Challenges in the Marcellus Unconventional Shale Play Using a New Steerable Motor with Optimized Design
Davila, Wilfredo (Baker Hughes) | Azizov, Azar (Baker Hughes) | Janwadkar, Sandeep (Baker Hughes) | Jones, Anthony (Baker Hughes) | Fabian, John (Baker Hughes) | Rowan, Tom (Gastar)
Abstract Although drilling horizontal wells in US-land unconventional shale plays has increased exponentially in the last few years, maximizing well productivity and improving drilling efficiency remains a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Drilling a curve with higher dogleg severity (DLS) reduces its verticalsection and maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays demand a DLS of 10 to 14 deg/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to bit; drilling in oriented mode limits the transfer of weight to the bit, reducing the rate-of-penetration (ROP). These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. Using the ODM helped the operator achieve higher build rates at lower AKO angle settings; rotate the BHA in well profiles where previously used motors could be operated only in slide mode, and maximize the length of curve interval drilled in rotary mode at higher rotations per minute (RPM). The new system significantly improved drilling performance with excellent directional control. Drilling high-DLS curves increased the length of laterals, enabling additional recovery of gas. This paper discusses the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Marcellus unconventional shale play.
- Europe (1.00)
- North America > United States > West Virginia (0.97)
- North America > United States > Virginia (0.72)
- (3 more...)
Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations
Ambrose, Ray J. (Devon Energy and University of Oklahoma) | Hartman, Robert C. (Weatherford Labs) | Diaz-Campos, Mery (University of Oklahoma) | Akkutlu, I. Yucel (University of Oklahoma) | Sondergeld, Carl H. (University of Oklahoma)
Summary Using focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material. Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases? We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8โ2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10โ25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.
- North America > Canada (0.93)
- North America > United States > Pennsylvania (0.68)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin (0.99)
- (5 more...)
Summary Shales and some tight-gas reservoirs have complex, multimodal pore-size distributions, including pore sizes in the nanopore range, causing gas to be transported by multiple flow mechanisms through the pore structure. Ertekin et al. (1986) developed a method to account for dual-mechanism (pressure- and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale-gas reservoirs, for which it is postulated that multimechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shale-gas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multimechanism flow in the inorganic- and organic-matter framework using the dynamic-slippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multimechanism flow in tight formations. Finally, we modify modern rate-transient-analysis methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate-transient-analysis methods for reservoirs exhibiting multimechanism (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale-gas and tight-gas formations because it captures the physics of flow in such formations realistically.
- North America > United States > Texas (0.29)
- North America > Canada > Alberta (0.29)
- North America > Canada > British Columbia (0.28)